Motor Integrated Reamer

ABSTRACT

In one aspect, an apparatus for use in a wellbore is disclosed that in one non-limiting embodiment may include a drive system coupled to a drill bit by a drive sub for drilling a wellbore, wherein the drive system has an associated bend for directional drilling of the wellbore, and a reamer driven by the drive sub, wherein the reamer reams a ledge formed at a transition from a larger diameter wellbore to a smaller diameter of the wellbore during directional drilling of the wellbore.

BACKGROUND

1. Field of the Disclosure

This disclosure relates generally to drilling assemblies for drillingdirectional wellbore.

2. Background of the Art

To obtain hydrocarbons, such as oil and gas, boreholes or wellbores aredrilled by rotating a drill bit attached to a drill string end. A largeproportion of the current drilling activity involves drilling deviatedand horizontal wellbores (directional wellbores) for hydrocarbonproduction. Drilling systems include a drill string that has a drillingassembly (commonly referred to as bottomhole assembly or “BHA”) thatincludes a drill bit attached to an end thereof. The BHA includes anumber of sensors, such as pressure, temperature, vibration andazimuthal sensors (commonly referred to a measurement-while-drilling(MWD) sensors) and tools for determining various properties of the earthformation (commonly referred to as logging-while-drilling “LWD” tool).BHA often includes a directional drilling device, which may be a bentsub or force application devices, such as ribs. For directionaldrilling, the BHA typically includes a motor, such as a positivedisplacement motor, driven by a drilling fluid (also referred to hereinas the “mud motor” or “drilling motor”) to rotate the drill bit.Typically a bent sub is integrated in the motor. There are two operatingmodes for directional drilling with bent motors. The first is mode isthe slide mode. In the slide mode, the drill string is not rotated. Themotor drills a curved section (in-gauge hole). The bend generates a sideforce at the drill bit, deflecting the drill string. The second mode isthe tangent mode. In the tangent mode, the drill string is rotated. Thebend and the side force do not have a deflecting impact on the drillstring. The motor drills straight ahead, but due to the bend, the holeis slightly oversized. If the next section is drilled in the slide mode,a ledge may be generated at the transition from the oversized hole tothe in-gauge hole, which may cause a stabilizer commonly used on abearing housing to hang up. This phenomenon has led to the use of slickmotors, which however, provide less directional control.

The disclosure herein provides apparatus and methods that reduce oreliminates the ledge and, thus, the potential hanging of the bearinghousing stabilizer.

SUMMARY OF THE DISCLOSURE

In one aspect, an apparatus for use in a wellbore is disclosed that inone non-limiting embodiment may include a motor coupled to a drill bitby a drive sub for drilling a wellbore, wherein the motor has anassociated bend for directional drilling of the wellbore, and a reamerdriven by the drive sub, wherein the reamer reams a ledge formed at atransition from a larger diameter wellbore to a smaller diameter of thewellbore during directional drilling of the wellbore.

In another aspect, a method of drilling a wellbore is disclosed that inone non-limiting embodiment may include: conveying a drilling assemblyby a rotatable conveying member into a wellbore, the drilling assemblyincluding a motor coupled to a drill bit, wherein the motor has anassociated bend, a stabilizer, and a reamer downhole of the stabilizer;drilling the wellbore by rotating the drill bit by the rotatableconveying member and the motor to form a first section having a firstsize; and drilling the wellbore by rotating the drill bit by the motoronly to form a second section of the wellbore, wherein transition fromthe first section to the second section includes a ledge; and utilizingthe reamer to reduce the ledge to form the wellbore.

Examples of certain features of the apparatus and method disclosedherein are summarized rather broadly in order that the detaileddescription thereof that follows may be better understood. There are, ofcourse, additional features of the apparatus and method disclosedhereinafter that will form the subject of the claims appended hereto.

BRIEF DESCRIPTION OF THE DRAWINGS

The disclosure herein is best understood with reference to theaccompanying figures in which like numerals have generally been assignedto like elements and in which:

FIG. 1 is an elevation view of a drilling system that includes a motorintegrated reamer according to one non-limiting embodiment of thedisclosure drilling a wellbore;

FIG. 2 shows placement of the motor and reamer on a drill collar,according to one non-limiting embodiment of the disclosure;

FIG. 3 shows an isometric cut-away view of the mechanism for driving therotor by the motor, according to one non-limiting environment of thedisclosure; and

FIG. 4 shows a simplified cross-section view of the device shown in FIG.3.

DESCRIPTION OF THE EMBODIMENTS

FIG. 1 is a schematic diagram of an exemplary drilling system 100 thatincludes a drill string 120 having a drilling assembly or a bottom holeassembly 190 attached to its bottom end. Drill string 120 is shownconveyed in a wellbore or borehole 126 being formed in a subsurfaceformation 195. The drilling system 100 includes a conventional derrick111 erected on a platform or floor 112 that supports a rotary table 114that is rotated by a prime mover, such as an electric motor (not shown),at a desired rotational speed. A tubing (such as jointed drill pipe)122, having the drilling assembly 190 attached at its bottom end,extends from the surface to the bottom 151 of the borehole 126. A drillbit 150, attached to drilling assembly 190, disintegrates the geologicalformations when it is rotated to drill the borehole 126. The drillstring 120 is coupled to a draw works 130 via a Kelly joint 121, swivel128 and line 129 through a pulley. Draw works 130 is operated to controlthe weight on bit (“WOB”). The drill string 120 may be rotated by a topdrive 114 a rather than the prime mover and the rotary table 114.

In one aspect, the drill bit 150 is rotated by rotating the drill pipe122. In another aspect, a drive system, such as downhole motor 160 (mudmotor) disposed in the drilling assembly 190 is utilized to rotate thedrill bit 150 alone or in addition to the drill string rotation. Thedrilling motor 160 includes a rotor that rotates a drive sub connectedto the drill bit 150 (described later in reference to FIG. 2).Alternatively, the drive system may include any other suitable device,including, but not limited to, a turbine.

In one aspect, a suitable drilling fluid 131 (also referred to as the“mud”) from a source 132 thereof, such as a mud pit, is circulated underpressure through the drill string 120 by a mud pump 134. The drillingfluid 131 passes from the mud pump 134 into the drill string 120 via adesurger 136 and a fluid line 138. The drilling fluid 131 a from thedrilling tubular 122 discharges at the borehole bottom 151 throughopenings in the drill bit 150. The returning drilling fluid 131 bcirculates uphole through the annular space or annulus 127 between thedrill string 120 and the borehole 126 and returns to the mud pit 132 viaa return line 135 and a screen 185 that removes the drill cuttings fromthe returning drilling fluid 131 b. A sensor S₁ in line 138 providesinformation about the flow rate of the fluid 131. Surface torque sensorS₂ and a sensor S₃ associated with the drill string 120 provideinformation about the torque and the rotational speed of the drillstring 120. Rate of penetration of the drill string 120 may bedetermined from sensor S₅, while the sensor S₆ may provide the hook loadof the drill string 120. Other sensors may be utilized to provideinformation about other parameters of interest.

Still referring to FIG. 1, a surface control unit or controller 140receives signals from downhole sensors and devices or tools via a sensor143 placed in the fluid line 138 and signals from sensors S₁-S₆ andother sensors used in the system 100 and processes such signalsaccording to programmed instructions provided by a program to thesurface control unit 140. The surface control unit 140 displays desireddrilling parameters and other information on a display/monitor 141 thatis utilized by an operator to control the drilling operations. Thesurface control unit 140 may be a computer-based unit that may include aprocessor 142 (such as a microprocessor), a storage device 144, such asa solid-state memory, tape or hard disc, etc., and one or more computerprograms 146 in the storage device 144 accessible to the processor 142for executing instructions contained in such programs. The surfacecontrol unit 140 may further communicate with a remote control unit 148.The surface control unit 140 may process data relating to the drillingoperations, data from the sensors and devices on the surface, datareceived from downhole devices and may control one or more operations ofthe drilling system 100.

Still referring to FIG. 1, the drilling assembly 190 may also containformation evaluation sensors or devices (also referred to asmeasurement-while-drilling, “MWD,” or logging-while-drilling, “LWD,”sensors) various properties of interest, such as resistivity, density,porosity, permeability, acoustic properties, nuclear-magnetic resonanceproperties, corrosive properties of the fluids or the formation, salt orsaline content, and other selected properties of the formation 195surrounding the drilling assembly 190. Such sensors are generally knownin the art and for convenience are collectively denoted herein bynumeral 165. The drilling assembly 190 may further include a variety ofother sensors and communication devices 159 for controlling and/ordetermining one or more functions and properties of the drillingassembly 190 (such as velocity, vibration, bending moment, acceleration,oscillations, whirl, stick-slip, etc.) and drilling operatingparameters, such as weight-on-bit, fluid flow rate, pressure,temperature, rate of penetration, azimuth, tool face, drill bitrotation, etc. The drill string 120 further includes a power generationdevice 178 configured to provide electrical power or energy to sensors165 and other devices 159 and other devices. A downhole controller 170may be provided to process signals from the various sensors and devicesin the drilling assembly 190 and to provide information about variousparameters of interest and to provide two-way communication with thesurface controller 140. In one aspect, the downhole controller 170 mayinclude a processor 172, such as a microprocessor, one or more storagedevices 174, such as solid state memories, and programs 176 accessibleto the processor 172 for executing instructions contained therein.

Still referring to FIG. 1, the drilling motor 160 includes a bend 180,known in the art, for drilling a deviated wellbore (directionaldrilling). Drilling motor 160 also includes a stabilizing device 182 ona housing 183 of the drilling motor 160 below the power section 155. Thestabilizing device may include any suitable device known in the art,including, but not limited to, a stabilizer and kick pads. The powersection 155 is connected to a drive sub (described later), which isconnected to the drill bit 150. In one non-limiting embodiment, thedrilling motor 160 further includes a reamer 185 below the stabilizer182 to prevent or reduce the forming of a ledge during directionaldrilling described in more detail in reference to FIGS. 2-4.

FIG. 2 shows a section of the motor (160, FIG. 1) that includes thepower section 155 that drives a drive sub 225 inside the stabilizer 182and reamer 185. As shown in FIG. 2, the power section 155 includes anouter housing 212 that may be lined with an elastomeric stator 214having a number of internal lobes 214 a and a solid rotor 216 havingexternal lobes 216 a that rotate inside the stator 214. When a fluid250, such as drilling fluid or drilling mud, under pressure is suppliedto the motor 155, the fluid passes through cavities 218 formed betweenthe stator 214 and the rotor 216, causing the rotor 216 to rotate. Therotor 216 is coupled to a drive sub 225 by a transmission element (notshown). The drill bit 150 is connected to the drive sub 225 via a boxend, known in the art. In the particular configuration of the device ofFIG. 2, the stabilizer 182 is provided below the power section 155 andthe reamer 185 below or downhole of the stabilizer 182. The reamer 185includes suitable cutters 240 configured to cut the rock formation.Cutters of various types are known in the art and are thus not describedin any detail herein. In one configuration, the reamer 185 may have theshape of a ring, as shown in FIG. 2. The reamer 185, however, may beconfigured to have any other suitable shape and may include any one ormore types of cutters, known in the art. In one aspect, the reamer 185is rotated by a mechanism (also referred to herein as the “reamer drive”or “drive mechanism”) operated by the power section 155 via the drivesub 225, as described below in more detail in reference to FIGS. 3 and4.

FIG. 3 shows a cut-away view of a non-limiting embodiment of a reamerdrive 300 driven by the power section 155 via the drive sub 225. FIG. 4shows a simplified cross-section view of the device shown in FIG. 3. Thedrive sub 225 is connected to the rotor (216, FIG. 2) of the powersection (155, FIG. 2) and, thus, it rotates as the motor rotates. Thedrive shaft is supported by axial bearings 327 (only downhole sidebearings shown) and radial bearings (not shown) of a bearing assembly329 inside a housing 302 of the drilling motor 160. In one non-limitingembodiment, the reamer drive 300 includes a first or inner gear wheel310 on the drive sub 225. The inner gear wheel has outer teeth 312 andit rotates when the drive sub 225 rotates. Thus, rotating the drive sub225 by the motor rotates the inner wheel 310 and hence teeth 312. Thereamer drive 300 also includes a second or outer gear wheel 330 disposedin a gear wheel housing 342 containing a number of seals 344, separatingthe drilling fluid 250 under high pressure inside the bearing assembly329 from the drilling fluid 250 under lower pressure in the annulus.Thus, in one aspect, the reamer drive contains seals that the pressurelevel inside the bearing assembly from the pressure level inside theannulus between the reamer and the wellbore. In an alternativeembodiment, the gear wheel housing 342 may be completely sealed from thedrilling fluid 131 allowing to use a lubricant such as oil. The outergear wheel 330 includes teeth 332 that on one end 332 a engage with theteeth 312 of the inner gear wheel 310 and on the other end 332 b engagewith teeth 387 on the inside of the reamer 185. Thus, when the drive sub225 rotates, the inner wheel 310 on the drive sub 225 rotates, whichrotates the outer wheel 330 and which in turn rotates the reamer 185.The ratio of the gears or teeth of inner gear wheel 310, the outer gearwheel 330 and the reamer 185 may be adjusted to provide a desiredrotational speed (rpm) of the reamer 185 relative to the rotation of thedrive sub 225. In one aspect, the gear wheel housing 342 includes one ormore ports or fluid passages 350 on opposite sides 336 a and 336 b ofthe gear wheel housing 342 to allow for the flow of the drilling fluidor mud 250 through the reamer drive 300. Flow of the fluid 250 throughthe reamer drive 300 is shown by arrows 360. The seals 344 separate thepressure level inside the bearing assembly from the pressure in theannulus.

Thus, in one aspect, a motor integrated reamer 185 is disclosed that inone non-limiting embodiment may be disposed on or integrated in abearing assembly 329 below a stabilizer 182. The reamer 185 also hereinis referred to as the motor integrated reamer. In one aspect, the reamer185 is rotated by the power section 155 via a first gear wheel 310 onthe drive sub 225, which rotates a second gear wheel 330 engaged to aninner teeth on the reamer 185. The second gear wheel 330 sits inside ahousing 342, but has mud ports 350 integrated in the gear wheel housing342 to allow passage of a coolant through the bearing assembly. Thecutters 240 on the downhole side of the reamer 185 ream the ledge formedat the transition of the over-gauge wellbore (wellbore formed when thedrill string is rotating) to the in-gauge wellbore (wellbore formed whenthe drill string is not rotating). Once the reamer 185 and thestabilizer 182 have passed the ledge, the contact to the borehole is onthe stabilizer 182 and the reamer rotates idle, because the reameroutside diameter is less than the diameter of the stabilizer.

While the foregoing disclosure is directed to the certain non-limitingexemplary embodiments of the disclosure, various modifications will beapparent to those skilled in the art. It is intended that all variationswithin the scope and spirit of the appended claims be embraced by theforegoing disclosure.

1. An apparatus for use in a wellbore, comprising: a drive systemcoupled to a drill bit by a drive sub for drilling a wellbore, whereinthe apparatus includes an associated bend for directional drilling ofthe wellbore; and a reamer driven by the drive sub, wherein the reamerreams a ledge formed at a transition from a larger diameter wellbore toa smaller diameter of the wellbore during directional drilling of thewellbore.
 2. The apparatus of claim 1 further comprising a reamer drivecoupled to the drive sub that rotates the reamer as the drive subrotates.
 3. The apparatus of claim 2 further comprising a bearingsection on the drive sub and wherein the reamer drive is placed on thebearing section.
 4. The apparatus of claim 2, wherein the reamer drivecomprises: a first gear wheel coupled to the drive sub, wherein thefirst gear wheel rotates when the drive sub rotates; and a second gearwheel coupled to the first gear wheel and the reamer, wherein the secondgear wheel rotates when the first gear wheel rotates to cause the reamerto rotate.
 5. The apparatus of claim 4, wherein rotational speed of thereamer is defined at least in part by sizes of the first gear wheel andthe second gear wheel.
 6. The apparatus of claim 1 further comprising: astabilizing device uphole of the reamer; and wherein outside diameter ofthe reamer is equal to or less than outside diameter of the stabilizingdevice and less than outside diameter of the drill bit.
 7. The apparatusof claim 4, wherein the reamer drive contains seals separating thepressure level inside the bearing assembly from the pressure levelinside the annulus between the reamer and the wellbore.
 8. The apparatusof claim 4, wherein the second gear is in a sealed housing with alubricant therein.
 9. The apparatus of claim 1, wherein the drive systemincludes one of: a drilling motor and a turbine.
 10. The apparatus ofclaim 4, wherein the second gear wheel is placed inside a housing thatis sealed to the inside of the bearing assembly and includes at leastone mud port to allow passage of a coolant through the bearing assembly.11. The apparatus of claim 10 further comprising additional seals togenerate an encapsulated cavity for the gear wheels to contain alubricant to provide lubrication to the reamer drive.
 12. A drillingsystem for directional drilling of a wellbore, comprising; a drillingassembly conveyable by a rotatable conveying member, wherein thedrilling assembly includes: a drive system coupled to a drill bit by adrive sub for drilling a wellbore, wherein the drilling assembly has anassociated bend for directional drilling of the wellbore; and a reamerdriven by the drive sub, wherein the reamer reams a ledge formed at atransition from a larger diameter wellbore to a smaller diameter of thewellbore during directional drilling of the wellbore.
 13. The drillingsystem of claim 12 further comprising a reamer drive coupled to thedrive sub that rotates the reamer as the drive sub rotates.
 14. Thedrilling system of claim 13, wherein the reamer drive comprises: a firstgear wheel coupled to a drive sub, wherein the first gear wheel rotateswhen the drive shaft rotates; and a second gear wheel coupled to thefirst gear wheel and the reamer, wherein the second gear wheel rotateswhen the first gear wheel rotates to cause the reamer to rotate.
 15. Thedrilling system of claim 12 further comprising a sensor for providingmeasurements relating to a property of interest during drilling of thewellbore.
 16. The drilling system of claim 12, wherein the drive systemincludes one of a motor and a turbine.
 17. A method of drilling awellbore, the method comprising: conveying a drilling assembly by arotatable conveying member into a wellbore, the drilling assemblyincluding a drive system coupled to a drill bit, an associated bend, anda reamer downhole of the stabilizing device; drilling the wellbore byrotating the drill bit with the rotatable conveying member and the drivesystem to form a first section having a first size; and drilling thewellbore by rotating the drill bit by only the drive system to form asecond section of the wellbore, wherein transition from the firstsection to the second section includes a ledge; and utilizing the reamerto reduce the ledge to form the wellbore.
 18. The method of claim 17further comprising determining one or more downhole parameters ofinterest during drilling of the wellbore and utilizing the determinedone or more parameters of interest to form a deviated wellbore.
 19. Themethod of claim 17, wherein the drilling assembly includes a stabilizingdevice and the outside diameter of the reamer is equal to or less thanthe outside diameter of the stabilizing device and less than the outsidediameter of the drill bit.
 20. The method of claim 17, wherein thereamer is driven by a reamer drive that includes: a first gear wheelcoupled to the drive sub, wherein the first gear wheel rotates when thedrive sub rotates; and a second gear wheel coupled to the first gearwheel and the reamer, wherein the second gear wheel rotates when thefirst gear wheel rotates to cause the reamer to rotate.